UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019
Commission file number 1-10447
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification Number) | |
(Address of principal executive offices including ZIP code)
(281 ) 589-4600
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Trading Symbol(s) | Name of each exchange on which registered |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
☒ | Accelerated filer | ☐ | Non-accelerated filer | ☐ | Smaller reporting company | Emerging growth company | ||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The aggregate market value of Common Stock, par value $.10 per share ("Common Stock"), held by non-affiliates as of the last business day of registrant's most recently completed second fiscal quarter (based upon the closing sales price on the New York Stock Exchange on June 28, 2019) was approximately $9.4 billion.
As of February 19, 2020, there were 398,575,510 shares of Common Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held April 30, 2020 are incorporated by reference into Part III of this report.
TABLE OF CONTENTS
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FORWARD-LOOKING INFORMATION
The statements regarding future financial and operating performance and results, strategic pursuits and goals, market prices, future hedging and risk management activities, and other statements that are not historical facts contained in this report are forward-looking statements. The words "expect," "project," "estimate," "believe," "anticipate," "intend," "budget," "plan," "forecast," "target," "predict," "may," "should," "could," "will" and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including geographic basis differentials) of natural gas, results of future drilling and marketing activity, future production and costs, legislative and regulatory initiatives, electronic, cyber or physical security breaches and other factors detailed herein and in our other Securities and Exchange Commission filings. Refer to "Risk Factors" in Item 1A for additional information about these risks and uncertainties. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.
GLOSSARY OF CERTAIN OIL AND GAS TERMS
The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and included within this Annual Report on Form 10-K:
Abbreviations
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of natural gas.
Bcfe. One billion cubic feet of natural gas equivalent.
Btu. One British thermal unit.
Dth. One million British thermal units.
Mbbl. One thousand barrels of oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of natural gas.
Mcfe. One thousand cubic feet of natural gas equivalent.
Mmbbl. One million barrels of oil or other liquid hydrocarbons.
Mmbtu. One million British thermal units.
Mmcf. One million cubic feet of natural gas.
Mmcfe. One million cubic feet of natural gas equivalent.
NGL. Natural gas liquids.
NYMEX. New York Mercantile Exchange.
Definitions
Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
Conventional play. A term used in the oil and gas industry to refer to an area believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps utilizing conventional recovery methods.
Developed reserves. Developed reserves are reserves that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating
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costs of support equipment and facilities and other costs of development activities, are costs incurred to: (i) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves, (ii) drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly, (iii) acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems, and (iv) provide improved recovery systems.
Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential. An adjustment to the price of oil or gas from an established spot market price to reflect differences in the quality and/or location of oil or gas.
Dry hole. Exploratory or development well that does not produce oil or gas in commercial quantities.
Exploitation activities. The process of the recovery of fluids from reservoirs and drilling and development of oil and gas reserves.
Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (i) costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs, (ii) costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records, (iii) dry hole contributions and bottom hole contributions, (iv) costs of drilling and equipping exploratory wells, and (v) costs of drilling exploratory-type stratigraphic test wells.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, or a service well.
Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geological barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
Gross acres. The total acres in which a working interest is owned.
Gross wells. The total wells in which a working interest is owned.
Net acres. The number of acres an owner has out of a particular number of gross acres. An owner who has a 30 percent working interest in 100 acres owns 30 net acres.
Net wells. The percentage ownership interest in a well that an owner has based on the working interest. An owner who has a 30 percent working interest in a well owns a 0.30 net well.
Oil. Crude oil and condensate.
Operator. The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease.
Play. A geographic area with potential oil and gas reserves.
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Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely not to be recovered.
Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities, which become part of the cost of oil and gas produced.
Proved properties. Properties with proved reserves.
Proved reserves. Proved reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions and operating methods prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.
Reliable technology. A grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonable certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.
Royalty interest. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowners' royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud.
Standardized measure. The present value, discounted at 10 percent per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices used in estimating proved oil and gas reserves to the year-end quantities of those reserves in effect as of the dates of such estimates and held constant throughout the productive life of the reserves (except for consideration of future price changes to the extent provided by contractual arrangements in existence at year-end), and deducting the estimated future costs to be incurred in developing, producing and abandoning the proved reserves (computed based on year-end costs and assuming continuation of existing economic conditions). Future income taxes are
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calculated by applying the appropriate year-end statutory federal and state income tax rate with consideration of future tax rates already legislated, to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to proved oil and gas reserves.
Unconventional play. A term used in the oil and gas industry to refer to a play in which the targeted reservoirs generally fall into one of three categories: (1) tight sands, (2) coal beds or (3) shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require fracture stimulation treatments or other special recovery processes in order to achieve economic flow rates.
Undeveloped reserves. Undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Unproved properties. Properties with no proved reserves.
Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.
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PART I
ITEMS 1 and 2. BUSINESS AND PROPERTIES
Cabot Oil & Gas Corporation is an independent oil and gas company engaged in the development, exploitation, exploration and production of oil and gas properties. Our assets are concentrated in areas with known hydrocarbon resources, which are conducive to multi-well, repeatable drilling programs. We operate in one segment, natural gas development, exploitation, exploration and production, in the continental United States. We have offices located in Houston, Texas and Pittsburgh, Pennsylvania.
STRATEGY
Our objective is to enhance shareholder value through the commodity price cycles by maintaining our disciplined approach to returns-focused capital allocation. While we operate in a cyclical industry, driven by the volatility of commodity prices, we believe that focusing on the following key components of our business strategy positions us to succeed on creating shareholder value through the commodity price cycles.
Focus on financial returns. Our goal is to generate financial returns that exceed our cost of capital by focusing on disciplined capital investment and maintaining a low cost structure. In 2019, our return on capital employed (non-GAAP) was 22.2 percent, an increase from 15.9 percent in 2018. Commodity prices play a critical role in our capital allocation decisions and have a significant impact on our financial returns.
Demonstrate continued cost control. Underpinning our financial returns is our continued focus on cost control, which resulted in an 18 percent reduction in operating expenses per unit in 2019 relative to 2018. We believe maintaining a low cost structure provides us with a competitive advantage, especially in a low natural gas price environment. We continue to assess additional opportunities to reduce our operating expenses per unit over time.
Maintain financial strength. We believe that maintaining a strong balance sheet with significant financial flexibility is imperative in a cyclical industry that is exposed to commodity price volatility. In recent years, we have reduced our absolute debt levels, and we anticipate retiring the current portion of our debt at maturity in 2020. We improved our total debt to total capitalization ratio from 37.0 percent at year-end 2018 to 36.2 percent at year-end 2019. Additionally, we ended 2019 with strong liquidity resulting from $200.2 million of cash and cash equivalents and $1.5 billion of unused commitments on our revolving credit facility.
Generate positive free cash flow. We believe generating positive free cash flow is paramount to creating shareholder value. Our disciplined approach to capital allocation allows us to adjust our capital spending and activity levels in response to commodity prices in order to maximize positive free cash flow through the price cycles. Our free cash flow is used for returning capital to shareholders, reducing debt levels and enhancing liquidity. In 2019, we generated $1.4 billion in cash flow from operations (GAAP) and $563.1 million of free cash flow (non-GAAP), representing our fourth consecutive year of positive free cash flow generation.
Return capital to shareholders. We currently target returning at least 50 percent of our free cash flow to shareholders annually through dividends and share repurchases. In 2019, we returned $665.4 million of capital to shareholders, representing 118 percent of our free cash flow for the year. We increased our dividend twice during 2019 and have increased our dividend five times since 2017. Since reinstating our share repurchase program in 2017, we have reduced our shares outstanding by over 14 percent. We plan to continue to prioritize returning capital to shareholders through all commodity price cycles.
Increase our proved reserve base. In 2019, we increased our year-end proved reserves by 11 percent at an all-sources finding and development cost (non-GAAP) of $0.36 per Mcfe. We also replaced 250 percent of our production for the year. We intend to continue to increase our proved reserves through our disciplined investment in the development of our Marcellus Shale asset assuming the commodity price environment provides for economic returns for our shareholders.
Refer to "Management's Discussion and Analysis of Financial Condition and Results of Operations - Non-GAAP Financial Measures" for a discussion and calculation of return on capital employed, free cash flow and finding and development cost, which are non-GAAP financial measures.
2020 OUTLOOK
Our 2020 capital program is expected to be approximately $575.0 million, a 27 percent reduction from our 2019 capital program of $783.3 million. We reduced our planned capital program as a result of the lower natural gas price environment. We expect to fund these expenditures with our operating cash flow and, if required, cash on hand.
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In 2020, our capital program will focus on the Marcellus Shale, where we expect to drill, complete and place on production 60 to 70 net wells. We allocate our planned program for capital expenditures based on market conditions, return on capital and free cash flow expectations and availability of services and human resources. We will continue to assess the natural gas price environment and may adjust our capital expenditures accordingly.
DESCRIPTION OF PROPERTIES
Our operations are primarily concentrated in one unconventional play—the Marcellus Shale in northeast Pennsylvania. Our Marcellus Shale properties represent our primary operating and growth area in terms of reserves, production and capital investment. Our properties are principally located in Susquehanna County, Pennsylvania, where we currently hold approximately 173,000 net acres in the dry gas window of the play. Our 2019 net production in the Marcellus Shale was 865 Bcfe, representing substantially all of our total equivalent production for the year. As of December 31, 2019, we had a total of 788.0 net wells in the Marcellus Shale, of which approximately 99.5 percent are operated by us.
During 2019, we invested $773.4 million in the Marcellus Shale and drilled or participated in drilling 94.0 net wells, completed 97.0 net wells and turned in line 97.0 net wells. As of December 31, 2019, we had 26.0 net wells that were either in the completion stage or waiting on completion or connection to a pipeline. We exited 2019 with three drilling rigs operating in the play and plan to exit 2020 with two rigs operating.
DIVESTITURES
In July 2018, we sold certain proved and unproved oil and gas properties in the Haynesville Shale to a third party for $30.0 million and recognized a gain on sale of oil and gas properties of $29.7 million.
In February 2018, we sold certain proved and unproved oil and gas properties in the Eagle Ford Shale to an affiliate of Venado Oil & Gas LLC for $765.0 million. During the fourth quarter of 2017, we recorded an impairment charge of $414.3 million associated with the proposed sale of these properties and upon closing recognized a loss on sale of oil and gas properties of $45.4 million.
In September 2017, we sold certain proved and unproved oil and gas properties and related pipeline assets located in West Virginia, Virginia and Ohio to an affiliate of Carbon Natural Gas Company for $41.3 million. During the second quarter of 2017, we recorded an impairment charge of $68.6 million associated with the proposed sale of these properties and upon closing the sale in the third quarter of 2017, we recognized a loss on sale of oil and gas properties of $11.9 million.
In February 2016, we sold certain proved and unproved oil and gas properties in east Texas to a third party for $56.4 million and recognized a $0.5 million gain on sale of assets.
MARKETING
Substantially all of our natural gas is sold at market sensitive prices under both long-term and short-term sales contracts and is subject to seasonal price swings. The principal markets for our natural gas are in the northeastern United States where we sell natural gas to industrial customers, local distribution companies, gas marketers and power generation facilities.
We also incur transportation and gathering expenses to move our natural gas production from the wellhead to our principal markets in the United States. The majority of our natural gas production is transported on third-party gathering systems and interstate pipelines where we have long-term contractual capacity arrangements or use purchaser-owned capacity under both long-term and short-term sales contracts.
To date, we have not experienced significant difficulty in transporting or marketing our natural gas production as it becomes available; however, there is no assurance that we will always be able to transport and market all of our production.
Delivery Commitments
We have entered into various firm sales contracts to deliver and sell natural gas. We believe we will have sufficient production quantities to meet substantially all of our commitments, but may be required to purchase natural gas from third parties to satisfy shortfalls should they occur.
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A summary of our firm sales commitments as of December 31, 2019 are set forth in the table below:
Natural Gas (Bcf) | |||
2020 | 624.0 | ||
2021 | 608.4 | ||
2022 | 567.6 | ||
2023 | 539.6 | ||
2024 | 521.6 | ||
We utilize a part of our firm transportation capacity to deliver natural gas under the majority of these firm sales contracts and have entered into numerous agreements for transportation of our production. Some of these contracts have volumetric requirements which could require monetary shortfall penalties if our production is inadequate to meet the terms. However, we do not believe we have a financial commitment due based on our current proved reserves and production levels from which we can fulfill these obligations.
RISK MANAGEMENT
From time to time, we use derivative financial instruments to manage price risk associated with our natural gas production. While there are many different types of derivatives available, we generally utilize collar, swap and basis swap agreements designed to manage price risk more effectively. The collar arrangements are a combination of put and call options used to establish floor and ceiling prices for a fixed volume of natural gas production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price falls below the floor. The swap agreements call for payments to, or receipts from, counterparties based on whether the index price for the period is greater or less than the fixed price established for the particular period under the swap agreement.
During 2019, natural gas basis swaps covered 63.8 Bcf, or seven percent, of natural gas production at an average price of $2.32 per Mcf. Natural gas swaps covered 226.1 Bcf, or 26 percent, of natural gas production at a weighted-average price of $3.30 per Mcf.
As of December 31, 2019, we had the following outstanding financial commodity derivatives:
Collars | |||||||||||||||||||||||
Floor | Ceiling | Swaps | |||||||||||||||||||||
Type of Contract | Volume (Mmbtu) | Contract Period | Range | Weighted- Average | Range | Weighted- Average | Weighted- Average ($/Mmbtu) | ||||||||||||||||
Natural gas (NYMEX) | 10,700,000 | Apr. 2020 - Oct. 2020 | $ | 2.27 | |||||||||||||||||||
Natural gas (NYMEX) | 10,700,000 | Apr. 2020 - Oct. 2020 | $ | — | $ | 2.15 | $2.36 - $2.38 | $ | 2.37 | ||||||||||||||
In early 2020, we entered into the following financial commodity derivatives:
Collars | |||||||||||||||||||||||||
Floor | Ceiling | Swaps | |||||||||||||||||||||||
Type of Contract | Volume (Mmbtu) | Contract Period | Range | Weighted- Average | Range | Weighted- Average | Weighted- Average ($/Mmbtu) | ||||||||||||||||||
Natural gas (NYMEX) | 10,700,000 | Apr. 2020 - Oct. 2020 | $ | 2.28 | |||||||||||||||||||||
Natural gas (NYMEX) | 10,700,000 | Apr. 2020 - Oct. 2020 | $ | — | $ | 2.15 | $ | — | $ | 2.38 | |||||||||||||||
A significant portion of our expected natural gas production for 2020 and beyond is currently unhedged and directly exposed to the volatility in natural gas market prices, whether favorable or unfavorable. We will continue to evaluate the benefit of using derivatives in the future. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Quantitative and Qualitative Disclosures about Market Risk" for further discussion related to our use of derivatives.
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RESERVES
The following table presents our estimated proved reserves for the periods indicated:
_______________________________________________________________________________
December 31, | ||||||||
2019 | 2018 | 2017 | ||||||
Natural Gas (Bcf) | ||||||||
Proved developed reserves | 8,056 | 7,402 | 6,001 | |||||
Proved undeveloped reserves(1) | 4,847 | 4,202 | 3,352 | |||||
12,903 | 11,604 | 9,353 | ||||||
Crude Oil & NGLs (Mbbl)(2) | ||||||||
Proved developed reserves | 22 | 107 | 31,066 | |||||
Proved undeveloped reserves(1) | — | 13 | 31,186 | |||||
22 | 120 | 62,252 | ||||||
Natural gas equivalent (Bcfe)(3) | 12,903 | 11,605 | 9,726 | |||||
Reserve life index (in years)(4) | 14.9 | 15.8 | 14.2 | |||||
(1) | Proved undeveloped reserves for 2019, 2018 and 2017 include reserves drilled but uncompleted of 783.2 Bcfe, 631.6 Bcfe and 807.4 Bcfe, respectively. |
(2) | There were no significant NGL reserves for 2019 and 2018, respectively. For 2017, NGL reserves were less than one percent of our total proved equivalent reserves and 13.7 percent of our proved crude oil and NGL reserves. |
(3) | Natural gas equivalents are determined using a ratio of 6 Mcf of natural gas to 1 Bbl of crude oil, condensate or NGLs. |
(4) | Reserve life index is equal to year-end proved reserves divided by annual production for the years ended December 31, 2019, 2018 and 2017, respectively. |
Our proved reserves at December 31, 2019 increased 1,298 Bcfe or 11 percent from 11,605 Bcfe at December 31, 2018. In 2019, we added 2,116 Bcfe of proved reserves through extensions, discoveries and other additions, primarily due to the results from our drilling and completion program in the Dimock field in northeast Pennsylvania. We also had a net upward revision of 47 Bcfe, which was primarily due to a net upward performance revision of 67 Bcfe, partially offset by a downward revision of 18 Bcfe associated with proved undeveloped (PUD) reserves reclassifications as a result of the five year limitation. The net upward performance revision of 67 Bcfe was primarily due to an upward revision of 417 Bcfe associated with our PUD reserves due to performance revisions and the drilling of longer lateral length wells, offset by a downward performance revision of 350 Bcfe related to certain proved developed producing properties. During 2019, we produced 865 Bcfe.
Since substantially all of our reserves are natural gas, our reserves are significantly more sensitive to natural gas prices and their effect on the economic productive life of producing properties. Our reserves are based on the 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month during the year. Increases in commodity prices may result in a longer economic productive life of a property or result in more economically viable proved undeveloped reserves to be recognized. Decreases in prices may result in negative impacts of this nature.
For additional information regarding estimates of proved reserves, the audit of such estimates by Miller and Lents, Ltd. (Miller and Lents) and other information about our reserves, including the risks inherent in our estimates of proved reserves, refer to the Supplemental Oil and Gas Information to the Consolidated Financial Statements included in Item 8 and “Risk Factors-Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A.
Technologies Used In Reserves Estimates
We utilize various traditional methods to estimate our reserves, including decline curve extrapolations, volumetric calculations and analogies, and in some cases a combination of these methods. In addition, at times we may use seismic interpretations to confirm continuity of a formation in combination with traditional technologies; however, seismic interpretations are not used in the volumetric computation.
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Internal Control
Our Senior Vice President, EHS and Engineering is the technical person responsible for our internal reserves estimation process and provides oversight of our corporate reservoir engineering department, which consists of two engineers, and the annual audit of our year-end reserves by Miller and Lents. He has a Bachelor of Science degree in Chemical Engineering, specializing in petroleum engineering, and over 37 years of industry experience with positions of increasing responsibility in operations, engineering and evaluations. He has worked in the area of reserves and reservoir engineering for 28 years and is a member of the Society of Petroleum Engineers.
Our reserves estimation process is coordinated by our corporate reservoir engineering department. Reserve information, including models and other technical data, are stored on secured databases on our network. Certain non-technical inputs used in the reserves estimation process, including commodity prices, production and development costs and ownership percentages, are obtained by other departments and are subject to testing as part of our annual internal control process. We also engage Miller and Lents, independent petroleum engineers, to perform an independent audit of our estimated proved reserves. Upon completion of the process, the estimated reserves are presented to senior management.
Miller and Lents has audited 100 percent of our proved reserves estimates and concluded, in their judgment, we have an effective system for gathering data and documenting information required to estimate our proved reserves and project our future revenues. Further, Miller and Lents has concluded (1) the reserves estimation methods employed by us were appropriate, and our classification of such reserves was appropriate to the relevant SEC reserve definitions, (2) our reserves estimation processes were comprehensive and of sufficient depth, (3) the data upon which we relied were adequate and of sufficient quality, and (4) the results of our estimates and projections are, in the aggregate, reasonable. A copy of the audit letter by Miller and Lents dated January 30, 2020, has been filed as an exhibit to this Annual Report on Form 10-K.
Qualifications of Third Party Engineers
The technical person primarily responsible for the audit of our reserves estimates at Miller and Lents meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Miller and Lents is an independent firm of petroleum engineers, geologists, geophysicists, and petro physicists; they do not own an interest in our properties and are not retained on a contingent fee basis.
Proved Undeveloped Reserves
At December 31, 2019, we had 4,847 Bcfe of PUD reserves associated with future development costs of $1.8 billion, which represents an increase of 645 Bcfe compared to December 31, 2018. All of our PUD reserves are located in Susquehanna County, Pennsylvania. We expect to complete substantially all of our PUD reserves associated with drilled but uncompleted wells by the end of 2020. Future development plans are reflective of the lower commodity price environment and have been established based on expected available cash flows from operations and availability under our revolving credit facility. As of December 31, 2019, all PUD reserves are expected to be drilled and completed within five years of initial disclosure of these reserves, with the exception of two drilled but uncompleted wells. These wells are scheduled to be completed in early 2020, just beyond the five-year period since initial disclosure, and together represent 1.6 percent of our total PUD reserves and less than 1.0 percent of our total proved reserves.
The following table is a reconciliation of the change in our PUD reserves (Bcfe):
Year Ended December 31, 2019 | ||
Balance at beginning of period | 4,202 | |
Transfers to proved developed | (1,542 | ) |
Additions | 1,788 | |
Revision of prior estimates | 399 | |
Balance at end of period | 4,847 | |
Changes in PUD reserves that occurred during the year were due to:
• | transfer of 1,542 Bcfe from PUD to proved developed reserves based on total capital expenditures of $473.1 million during 2019; |
• | new PUD reserve additions of 1,788 Bcfe in the Dimock field in northeast Pennsylvania; and |
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• | upward PUD reserve revisions of 399 Bcfe resulting from upward performance revisions of 417 Bcfe associated with performance revisions along with the drilling of longer lateral wells, partially offset by downward revisions of 18 Bcfe associated with PUD reclassifications as a result of the five year limitation. |
PRODUCTION, SALES PRICE AND PRODUCTION COSTS
The following table presents historical information about our production volumes for natural gas and oil (including NGLs), average natural gas and crude oil sales prices, and average production costs per equivalent, including our Dimock field located in northeast Pennsylvania, which represents more than 15 percent of our total proved reserves:
_______________________________________________________________________________
Year Ended December 31, | |||||||||||
2019 | 2018 | 2017 | |||||||||
Production Volumes | |||||||||||
Natural gas (Bcf) | |||||||||||
Dimock field | 865.0 | 729.1 | 641.7 | ||||||||
Total | 865.3 | 729.9 | 655.6 | ||||||||
Oil (Mbbl)(1) | |||||||||||
Total | — | 829 | 4,953 | ||||||||
Equivalents (Bcfe) | |||||||||||
Dimock field | 865.0 | 729.1 | 641.7 | ||||||||
Total | 865.3 | 735.0 | 685.3 | ||||||||
Natural Gas Average Sales Price ($/Mcf) | |||||||||||
Dimock field | $ | 2.29 | $ | 2.58 | $ | 2.33 | |||||
Total (excluding realized impact of derivative settlements) | $ | 2.29 | $ | 2.58 | $ | 2.30 | |||||
Total (including realized impact of derivative settlements) | $ | 2.45 | $ | 2.54 | $ | 2.31 | |||||
Oil Average Sales Price ($/Bbl) | |||||||||||
Total (excluding realized impact of derivative settlements) | $ | — | $ | 64.51 | $ | 47.81 | |||||
Total (including realized impact of derivative settlements) | $ | — | $ | 63.53 | $ | 48.16 | |||||
Average Production Costs ($/Mcfe) | |||||||||||
Dimock field | $ | 0.06 | $ | 0.05 | $ | 0.04 | |||||
Total | $ | 0.06 | $ | 0.05 | $ | 0.11 | |||||
(1) | There was no significant NGL production for the year ended December 31, 2019. NGL production represented less than one percent of our equivalent production for the years ended December 31, 2018 and 2017, and 8.5 percent, and 10.3 percent of our crude oil production for the years ended December 31, 2018 and 2017, respectively. |
ACREAGE
Our interest in both developed and undeveloped properties is primarily in the form of leasehold interests held under customary mineral leases. These leases provide us the right to develop oil and/or natural gas on the properties. Their primary terms range in length from approximately three to 10 years. These properties are held for longer periods if production is established.
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The following table summarizes our gross and net developed and undeveloped leasehold and mineral fee acreage at December 31, 2019:
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Developed | Undeveloped (1) | Total | |||||||||||||||
Gross | Net | Gross | Net | Gross | Net | ||||||||||||
Leasehold acreage | 155,997 | 153,799 | 894,123 | 777,600 | 1,050,120 | 931,399 | |||||||||||
Mineral fee acreage | 877 | 877 | 177,481 | 149,301 | 178,358 | 150,178 | |||||||||||
Total | 156,874 | 154,676 | 1,071,604 | 926,901 | 1,228,478 | 1,081,577 | |||||||||||
Includes leasehold and mineral fee net acreage of 585,686 and 147,371, respectively, associated with deep formations located in West Virginia and Virginia. Substantially all of this leasehold is held by production from shallower formations that are operated by others.
Total Net Undeveloped Acreage Expiration
In the event that production is not established or we take no action to extend or renew the terms of our leases, our net undeveloped acreage that will expire over the next three years as of December 31, 2019 is 78,534, 13,747 and 3,998 for the years ending December 31, 2020, 2021 and 2022, respectively.
As of December 31, 2019, less than one percent of our expiring acreage disclosed above is located in our primary operating areas where we currently expect to continue exploration and development activities and/or extend the lease terms. There were no PUD reserves recorded on any of our expiring acreage disclosed above.
WELL SUMMARY
The following table presents our ownership in productive natural gas and crude oil wells at December 31, 2019. This summary includes natural gas and crude oil wells in which we have a working interest:
_______________________________________________________________________________
Gross | Net | ||||
Natural gas | 850 | 789.0 | |||
Crude oil | 17 | 1.8 | |||
Total(1) | 867 | 790.8 | |||
(1) | Total percentage of gross operated wells is 90.7 percent. |
DRILLING ACTIVITY
We drilled and completed wells or participated in the drilling and completion of wells as indicated in the table below. The information below should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.
Year Ended December 31, | |||||||||||||||||
2019 | 2018 | 2017 | |||||||||||||||
Gross | Net | Gross | Net | Gross | Net | ||||||||||||
Development Wells | |||||||||||||||||
Productive | 96 | 94.0 | 85 | 84.0 | 104 | 93.2 | |||||||||||
Dry | — | — | — | — | — | — | |||||||||||
Exploratory Wells | |||||||||||||||||
Productive | — | — | — | — | — | — | |||||||||||
Dry | — | — | 9 | 9.0 | 1 | 1.0 | |||||||||||
Total | 96 | 94.0 | 94 | 93.0 | 105 | 94.2 | |||||||||||
Acquired Wells | — | — | — | — | — | — | |||||||||||
During the year ended December 31, 2019, we completed 29 gross wells (29.0 net) that were drilled in prior years.
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The following table sets forth information about wells for which drilling was in progress or which were drilled but uncompleted at December 31, 2019, which are not included in the above table:
Drilling In Progress | Drilled But Uncompleted | |||||||||||
Gross | Net | Gross | Net | |||||||||
Development wells | 11 | 11.0 | 26 | 26.0 | ||||||||
Exploratory wells | — | — | — | — | ||||||||
Total | 11 | 11.0 | 26 | 26.0 | ||||||||
OTHER BUSINESS MATTERS
Title to Properties
We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalty, overriding royalty, carried, net profits, working and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary course liens incidental to operating agreements and for current taxes or development obligations under oil and gas leases. As is customary in the industry in the case of undeveloped properties, preliminary investigations of record title are made at the time of lease acquisition. Complete investigations are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.
Competition
The oil and gas industry is highly competitive and we experience strong competition in our primary producing areas. We primarily compete with integrated, independent and other energy companies for the sale and transportation of our natural gas production to marketing companies and end users. Furthermore, the oil and gas industry competes with other energy industries that supply fuel and power to industrial, commercial and residential consumers. Many of these competitors have greater financial, technical and personnel resources. The effect of these competitive factors cannot be predicted.
Price, contract terms, availability of rigs and related equipment and quality of service, including pipeline connection times and distribution efficiencies affect competition. We believe that our extensive acreage position and our access to gathering and pipeline infrastructure in Pennsylvania, along with our expected activity level and the related services and equipment that we have secured for the upcoming years, enhance our competitive position over other producers who do not have similar systems or services in place.
Major Customers
During the year ended December 31, 2019, three customers accounted for approximately 17 percent, 16 percent and 16 percent of our total sales. During the year ended December 31, 2018, two customers accounted for approximately 20 percent and 11 percent of our total sales. During the year ended December 31, 2017, two customers accounted for approximately 18 percent and 11 percent of our total sales. We do not believe that the loss of any of these customers would have a material adverse effect on us because alternative customers are readily available.
Seasonality
Demand for natural gas has historically been seasonal, with peak demand and typically higher prices occurring during the winter months.
Regulation of Oil and Natural Gas Exploration and Production
Exploration and production operations are subject to various types of regulation at the federal, state and local levels. This regulation includes requiring permits to drill wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties on which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells that may be drilled in a given field and the unitization or pooling of oil and natural gas properties. Some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of oil and natural gas we can produce from our wells, and to limit the number of wells or the locations
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where we can drill. Because these statutes, rules and regulations undergo constant review and often are amended, expanded and reinterpreted, we are unable to predict the future cost or impact of regulatory compliance. The regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability. We do not believe, however, we are affected differently by these regulations than others in the industry.
Natural Gas Marketing, Gathering and Transportation
Federal legislation and regulatory controls have historically affected the price of the natural gas we produce and the manner in which our production is transported and marketed. Under the Natural Gas Act of 1938 (NGA), the Natural Gas Policy Act of 1978 (NGPA), and the regulations promulgated under those statutes, the Federal Energy Regulatory Commission (FERC) regulates the interstate sale for resale of natural gas and the transportation of natural gas in interstate commerce, although facilities used in the production or gathering of natural gas in interstate commerce are generally exempted from FERC jurisdiction. Effective beginning in January 1993, the Natural Gas Wellhead Decontrol Act deregulated natural gas prices for all “first sales” of natural gas, which definition covers all sales of our own production. In addition, as part of the broad industry restructuring initiatives described below, the FERC granted to all producers such as us a “blanket certificate of public convenience and necessity” authorizing the sale of natural gas for resale without further FERC approvals. As a result of this policy, all of our produced natural gas is sold at market prices, subject to the terms of any private contracts that may be in effect. In addition, under the provisions of the Energy Policy Act of 2005 (2005 Act), the NGA was amended to prohibit any forms of market manipulation in connection with the purchase or sale of natural gas. Pursuant to the 2005 Act, the FERC established regulations intended to increase natural gas pricing transparency by, among other things, requiring market participants to report their gas sales transactions annually to the FERC. The 2005 Act also significantly increased the penalties for violations of the NGA and NGPA and the FERC’s regulations thereunder up to $1,000,000 per day per violation. This maximum penalty authority established by statute has been and will continue to be adjusted periodically for inflation. As of December 31, 2019, the maximum penalty amount was $1,269,500 per day per violation. In 2010, the FERC issued Penalty Guidelines for the determination of civil penalties and procedure under its enforcement program.
Our production and gathering facilities are not subject to FERC jurisdiction; however, our natural gas sales prices nevertheless continue to be affected by intrastate and interstate gas transportation regulation because the cost of transporting the natural gas once sold to the consuming market is a factor in the prices we receive. Beginning with Order No. 436 in 1985 and continuing through Order No. 636 in 1992 and Order No. 637 in 2000, the FERC has adopted a series of rulemakings that have significantly altered the transportation and marketing of natural gas. These changes were intended by the FERC to foster competition by, among other things, requiring interstate pipeline companies to separate their wholesale gas marketing business from their gas transportation business, and by increasing the transparency of pricing for pipeline services. The FERC has also established regulations governing the relationship of pipelines with their marketing affiliates, which essentially require that designated employees function independently of each other, and that certain information not be shared. The FERC has also implemented standards relating to the use of electronic data exchange by the pipelines to make transportation information available on a timely basis and to enable transactions to occur on a purely electronic basis.
In light of these statutory and regulatory changes, most pipelines have divested their natural gas sales functions to marketing affiliates, which operate separately from the transporter and in direct competition with all other merchants. Most pipelines have also implemented the large‑scale divestiture of their natural gas gathering facilities to affiliated or non-affiliated companies. Interstate pipelines are required to provide unbundled, open and nondiscriminatory transportation and transportation‑related services to producers, gas marketing companies, local distribution companies, industrial end users and other customers seeking such services. As a result of the FERC requiring natural gas pipeline companies to separate marketing and transportation services, sellers and buyers of natural gas have gained direct access to pipeline transportation services, and are better able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to markets while, at the same time, substantially increasing competition in the natural gas marketplace. We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Similarly, we cannot predict what proposals, if any, that affect the oil and natural gas industry might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on us. Further, we cannot predict whether the recent trend toward federal deregulation of the natural gas industry will continue or what effect future policies will have on our sale of gas.
Federal Regulation of Swap Transactions
We use derivative financial instruments such as collar, swap and basis swap agreements to attempt to more effectively manage price risk due to the impact of changes in commodity prices on our operating results and cash flows. Following enactment of the Dodd‑Frank Wall Street Reform and Consumer Protection Act (Dodd‑Frank Act) in July 2010, the Commodity Futures Trading Commission (CFTC) has promulgated regulations to implement statutory requirements for swap transactions, including certain options. The CFTC regulations are intended to implement a regulated market in which most swaps are
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executed on registered exchanges or swap execution facilities and cleared through central counterparties. In addition, all swap market participants are subject to new reporting and recordkeeping requirements related to their swap transactions. We believe that our use of swaps to hedge against commodity exposure qualifies us as an end‑user, exempting us from the requirement to centrally clear our swaps. Nevertheless, changes to the swap market as a result of Dodd‑Frank implementation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps. If we reduce our use of swaps as a result of the Dodd‑Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.
Federal Regulation of Petroleum
Sales of crude oil and NGLs are not regulated and are made at market prices. However, the price received from the sale of these products is affected by the cost of transporting the products to market. Much of that transportation is through interstate common carrier pipelines, which are regulated by the FERC under the Interstate Commerce Act (ICA). FERC requires that pipelines regulated under the ICA file tariffs setting forth the rates and terms and conditions of service and that such service not be unduly discriminatory or preferential.
Effective January 1, 1995, the FERC implemented regulations generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. These regulations may increase or decrease the cost of transporting crude oil and NGLs by interstate pipeline, although the annual adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In December 2015, to implement this required five‑year re‑determination, the FERC established an upward adjustment in the index to track oil pipeline cost changes and determined that the Producer Price Index for Finished Goods plus 1.23 percent should be the oil pricing index for the five‑year period beginning July 1, 2016. The result of indexing is a “ceiling rate” for each rate, which is the maximum at which the pipeline may set its interstate transportation rates. A pipeline may also file cost‑of‑service based rates if rate indexing will be insufficient to allow the pipeline to recover its costs. Rates are subject to challenge by protest when they are filed or changed. For indexed rates, complaints alleging that the rates are unjust and unreasonable may only be pursued if the complainant can show that a substantial change has occurred since the enactment of Energy Policy Act of 1992 in either the economic circumstances of the pipeline or in the nature of the services provided that were a basis for the rate. There is no such limitation on complaints alleging that the pipeline’s rates or terms and conditions of service are unduly discriminatory or preferential. We are unable to predict with certainty the effect upon us of these periodic reviews by the FERC of the pipeline index, or any potential future challenges to pipelines' rates.
Environmental and Safety Regulations
General. Our operations are subject to extensive federal, state and local laws and regulations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Permits are required for the operation of our various facilities. These permits can be revoked, modified or renewed by issuing authorities. Governmental authorities enforce compliance with their regulations through fines, injunctions or both. Government regulations can increase the cost of planning, designing, installing and operating, and can affect the timing of installing and operating, oil and natural gas facilities. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities related to environmental compliance issues are part of oil and natural gas production operations. No assurance can be given that significant costs and liabilities will not be incurred. Also, it is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and natural gas production could result in substantial costs and liabilities to us.
U.S. laws and regulations applicable to our operations include those controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment or otherwise relating to the protection of the environment.
Solid and Hazardous Waste. We currently own or lease, and have in the past owned or leased, numerous properties that were used for the production of oil and natural gas for many years. Although operating and disposal practices that were standard in the industry at the time may have been utilized, it is possible that hydrocarbons or other wastes may have been disposed of or released on or under the properties currently owned or leased by us. State and federal laws applicable to oil and gas wastes and properties have become stricter over time. Under these increasingly stringent requirements, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners and operators) or clean up property contamination (including groundwater contamination by prior owners or operators) or to perform plugging operations to prevent future contamination.
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We generate some hazardous wastes that are subject to the Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes, as well as wastes that are exempt from such regulation. The Environmental Protection Agency (EPA) has limited the disposal options for certain hazardous wastes. It is possible that certain wastes currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes under RCRA or other applicable statutes. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess the need to regulate exploration and production related oil and gas wastes exempt from regulation as hazardous wastes under RCRA under Subtitle D applicable to non-hazardous solid waste. The consent decree required the EPA to propose a rulemaking by March 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or to sign a determination that revision of the regulations is not necessary. In April 2019, the EPA issued its determination that based on its review, including consideration of state regulatory programs, it was not necessary at the time to revise Subtitle D regulations to address the management of oil and gas wastes. In the future, we could be subject to more rigorous and costly disposal requirements than we encounter today.
Superfund. The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), also known as the “Superfund” law, and comparable state laws and regulations impose liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release of hazardous substances into the environment. These persons include the current and past owners and operators of a site where the release occurred and any party that treated or disposed of or arranged for the treatment or disposal of hazardous substances found at a site. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA, and in some cases, private parties, to undertake actions to clean up such hazardous substances, or to recover the costs of such actions from the responsible parties. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of business, we have used materials and generated wastes and will continue to use materials and generate wastes that may fall within CERCLA’s definition of hazardous substances. We may also be an owner or operator of sites on which hazardous substances have been released. As a result, we may be responsible under CERCLA for all or part of the costs to clean up sites where such substances have been released.
Oil Pollution Act. The Federal Oil Pollution Act of 1990 (OPA) and resulting regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The term “waters of the United States” has been broadly defined to include inland water bodies, including wetlands and intermittent streams. The OPA assigns joint and several strict liability to each responsible party for oil removal costs and a variety of public and private damages. The OPA also imposes ongoing requirements on operators, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. We believe that we substantially comply with the Oil Pollution Act and related federal regulations.
Endangered Species Act. The Endangered Species Act (ESA) restricts activities that may affect endangered or threatened species or their habitats. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA, nor are we aware of any proposed listings that will affect our operations. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.
Clean Water Act. The Federal Water Pollution Control Act (Clean Water Act) and implementing regulations, which are primarily executed through a system of permits, also govern the discharge of certain contaminants into waters of the United States. Sanctions for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease construction or operation of certain facilities or to cease hauling wastewaters to facilities owned by others that are the source of water discharges. We believe that we substantially comply with the Clean Water Act and related federal and state regulations.
Clean Air Act. Our operations are subject to the Federal Clean Air Act and comparable local and state laws and regulations to control emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control toxic air pollutants and greenhouse gases might require installation of additional controls. Payment of fines and correction of any identified deficiencies generally resolve penalties for failure to comply strictly with air regulations or permits. Regulatory agencies could also require us to cease construction or operation of certain facilities or to install additional controls on certain facilities that are air emission sources. We believe that we substantially comply with applicable emission standards under local, state, and federal laws and regulations.
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Some of our producing wells and associated facilities are subject to restrictive air emission limitations and permitting requirements. In 2012, the EPA published final New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP) that amended the existing NSPS and NESHAP standards for oil and gas facilities and created new NSPS standards for oil and natural gas production, transmission and distribution facilities. In June 2016, the EPA published a final rule that updates and expands the NSPS by setting additional emissions limits for volatile organic compounds and regulating methane emissions for new and modified sources in the oil and gas industry. In addition, in June 2017, the EPA proposed a two year stay of certain requirements contained in June 2016 rule and in November 2017 issued a notice of data availability in support of the stay proposal and provided a 30-day comment period on the information provided. In March 2018, the EPA published a final rule that amended two narrow provisions of the NSPS including removing the requirement for completion of delayed repair during emergency or unscheduled vent blowdowns. The EPA also published a final rule in June 2016 concerning aggregation of sources that affects source determinations for air permitting in the oil and gas industry. In September 2019, the EPA published a proposal to rescind the 2012 and 2016 NSPS rules applicable to sources in the transmission and storage segment of the oil and gas industry and to rescind the methane requirements applicable to sources in the production and processing segments. In its September 2019 proposal, as an alternative, the EPA proposed the rescission of all of the new source performance standards applicable to all oil and natural gas sources in the source category without otherwise undoing the 2012 and 2016 NSPS rules. In October 2015, the EPA adopted a lower national ambient air quality standard for ozone. The revised standard could result in additional areas being designated as ozone non-attainment, which could lead to requirements for additional emissions control equipment and the imposition of more stringent permit requirements on facilities in those areas. The EPA completed its final area designations under the new ozone standard in July 2018. If we are unable to comply with air pollution regulations or to obtain permits for emissions associated with our operations, we could be required to forego construction, modification or certain operations. These regulations may also increase compliance costs for some facilities we own or operate, and result in administrative, civil and/or criminal penalties for non-compliance. Obtaining permits may delay the development of our oil and natural gas projects, including the construction and operation of facilities.
Safe Drinking Water Act. The Safe Drinking Water Act (SDWA) and comparable local and state provisions restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance for some facilities.
Hydraulic Fracturing. Many of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and natural gas wells. This technology involves the injection of fluids, usually consisting mostly of water but typically including small amounts of several chemical additives, as well as sand into a well under high pressure in order to create fractures in the formation that allow oil or natural gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Due to concerns raised relating to potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal, state and local levels have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and natural gas production activities using hydraulic fracturing techniques which could have an adverse effect on oil and natural gas production activities, including operational delays or increased operating costs in the production of oil and natural gas from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells and increased compliance costs, which could increase costs of our operations and cause considerable delays in acquiring regulatory approvals to drill and complete wells. In addition, if existing laws and regulations with regard to hydraulic fracturing are revised or reinterpreted or if new laws and regulations become applicable to our operations through judicial or administrative actions, our business, financial condition, results of operations and cash flows could be adversely affected. For additional information about hydraulic fracturing and related environmental matters, please read “Risk Factors-Federal and state legislation, judicial actions and regulatory initiatives related to oil and gas development, including hydraulic fracturing, could result in increased costs and operating restrictions or delays and adversely affect our business, financial condition, results of operations and cash flows” in Item 1A.
Greenhouse Gas. In response to studies suggesting that emissions of carbon dioxide and certain other gases may be contributing to global climate change, the United States Congress has considered, but not enacted, legislation to reduce emissions of greenhouse gases from sources within the United States between 2012 and 2050. In addition, many states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The EPA has also begun to regulate carbon dioxide and other greenhouse gas emissions under existing provisions of the Clean Air Act. This includes potential regulation of methane emissions from new and modified sources in the oil and gas sector. If we are unable to recover
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or pass through a significant portion of our costs related to complying with current and future regulations relating to climate change and GHGs, it could materially affect our operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of, and access to, capital. Future legislation or regulations adopted to address climate change could also make our products more or less desirable than competing sources of energy. Please read “Risk Factors-Climate change and climate change legislative and regulatory initiatives could result in increased operating costs and decreased demand for the oil and natural gas that we produce” in Item 1A.
OSHA and Other Laws and Regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (OSHA), and comparable state laws. The OSHA hazard communication standard, the EPA community right‑ to‑know regulations under the Title III of CERCLA and similar state laws require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards related to workplace exposure to hazardous substances and employee health and safety.
Employees
As of December 31, 2019, we had 274 employees associated with our upstream operations. In addition, we had 273 employees that are employed by our wholly-owned subsidiary, GasSearch Drilling Services Corporation. We recognize that our success is significantly influenced by the relationship we maintain with our employees. Overall, we believe that our relations with our employees are satisfactory. Our employees are not represented by a collective bargaining agreement.
Website Access to Company Reports
We make available free of charge through our website, www.cabotog.com, our annual reports on Form 10‑K, quarterly reports on Form 10‑Q, current reports on Form 8‑K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission (SEC). Information on our website is not a part of this report. In addition, the SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information filed by us.
Corporate Governance Matters
Our Corporate Governance Guidelines, Corporate Bylaws, Audit Committee Charter, Compensation Committee Charter, Corporate Governance and Nominations Committee Charter, Code of Business Conduct and Safety and Environmental Affairs Committee Charter are available on our website at www.cabotog.com, under the “Governance” section of “About Cabot.” Requests can also be made in writing to Investor Relations at our corporate headquarters at Three Memorial City Plaza, 840 Gessner Road, Suite 1400, Houston, Texas 77024.
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ITEM 1A. RISK FACTORS
Commodity prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business.
Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prices we receive for the natural gas that we sell. Lower commodity prices may reduce the amount of natural gas that we can produce economically. Historically, commodity prices have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile. Because substantially all of our reserves are natural gas, changes in natural gas prices have a more significant impact on our financial results. Natural gas prices, based on the NYMEX Henry Hub Natural Gas Futures Final Settlement prices, were $3.642 per Mmbtu in January 2019 and $2.470 per Mmbtu in December 2019. Prices have continued to decline to $1.877 per Mmbtu in February 2020. Any substantial or extended decline in future commodity prices would have, a material adverse effect on our future business, financial condition, results of operations, cash flows, liquidity or ability to finance planned capital expenditures and commitments. Furthermore, substantial, extended decreases in commodity prices may cause us to delay or postpone a significant portion of our exploration, development and exploitation projects or may render such projects uneconomic, which may result in significant downward adjustments to our estimated proved reserves and could negatively impact our ability to borrow and cost of capital and our ability to access capital markets, increase our costs under our revolving credit facility, and limit our ability to execute aspects of our business plans. Refer to "Risk Factors-Future commodity price declines may result in write-downs of the carrying amount of our oil and gas properties, which could materially and adversely affect our results of operations."
Wide fluctuations in commodity prices may result from relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. These factors include but are not limited to the following:
• | the levels and location of natural gas and oil supply and demand and expectations regarding supply and demand, including the potential long-term impact of an abundance of natural gas from shale (such as that produced from our Marcellus Shale properties) on the global natural gas supply; |
• | the level of consumer demand for natural gas and oil; |
• | weather conditions; |
• | political conditions or hostilities in natural gas and oil producing regions, including the Middle East, Africa, South America and the United States; |
• | the ability and willingness of the members of the Organization of Petroleum Exporting Countries and other exporting nations to agree to and maintain oil price and production controls; |
• | the price level and quantities of foreign imports; |
• | actions of governmental authorities; |
• | the availability, proximity and capacity of gathering, transportation, processing and/or refining facilities in regional or localized areas that may affect the realized price for natural gas and oil; |
• | inventory storage levels; |
• | the nature and extent of domestic and foreign governmental regulations and taxation, including environmental and climate change regulation; |
• | the price, availability and acceptance of alternative fuels; |
• | technological advances affecting energy consumption; |
• | speculation by investors in oil and natural gas; |
• | variations between product prices at sales points and applicable index prices; and |
• | overall economic conditions, including the value of the U.S. dollar relative to other major currencies. |
These factors and the volatile nature of the energy markets make it impossible to predict the future commodity prices. If commodity prices remain low or continue to decline significantly for a sustained period of time, the lower prices may cause us
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to reduce our planned drilling program or adversely affect our ability to make planned expenditures, raise additional capital or meet our financial obligations.
Drilling natural gas and oil wells is a high-risk activity.
Our growth is materially dependent upon the success of our drilling program. Drilling for natural gas and oil involves numerous risks, including the risk that no commercially productive reservoirs will be encountered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors beyond our control, including:
• | decreases in commodity prices; |
• | unexpected drilling conditions, pressure or irregularities in formations; |
• | equipment failures or accidents; |
• | adverse weather conditions; |
• | surface access restrictions; |
• | loss of title or other title related issues; |
• | lack of available gathering or processing facilities or delays in the construction thereof; |
• | compliance with, or changes in, governmental requirements and regulation, including with respect to wastewater disposal, discharge of greenhouse gases and fracturing; and |
• | costs of shortages or delays in the availability of drilling rigs or crews and the delivery of equipment and materials. |
Our future drilling activities may not be successful and, if unsuccessful, such failure will have an adverse effect on our future results of operations and financial condition. Our overall drilling success rate or our drilling success rate within a particular geographic area may decline. We may be unable to lease or drill identified or budgeted prospects within our expected time frame, or at all. We may be unable to lease or drill a particular prospect because, in some cases, we identify a prospect or drilling location before seeking an option or lease rights in the prospect or location. Similarly, our drilling schedule may vary from our capital budget. The final determination with respect to the drilling of any scheduled or budgeted wells will be dependent on a number of factors, including:
• | the results of exploration efforts and the acquisition, review and analysis of seismic data; |
• | the availability of sufficient capital resources to us and the other participants for the drilling of the prospects; |
• | the approval of the prospects by other participants after additional data has been compiled; |
• | economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability of drilling rigs and crews; |
• | our financial resources and results; and |
• | the availability of leases and permits on reasonable terms for the prospects and any delays in obtaining such permits. |
These projects may not be successfully developed and the wells, if drilled, may not encounter reservoirs of commercially productive natural gas or oil.
Our proved reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated
Reserve engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently imprecise, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as commodity prices. Additional assumptions include drilling and operating expenses, capital expenditures, taxes and availability of funds. Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data.
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Results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates often vary from the quantities of natural gas and oil that are ultimately recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves.
As of December 31, 2019, approximately 38 percent of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans to make capital expenditures for estimated future development costs of $1.8 billion to convert our PUD reserves into proved developed reserves. The estimated future development costs associated with our PUD reserves may not equal our actual costs, development may not occur as scheduled and results may not be as estimated. If we choose not to develop our PUD reserves, or if we are not otherwise able to successfully develop them, we will be required to remove them from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, because PUD reserves generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any PUD reserves that are not developed within this five-year time frame.
You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10 percent discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the applicable accounting standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.
Future commodity price declines may result in write-downs of the carrying amount of our oil and gas properties, which could materially and adversely affect our results of operations.
The value of our oil and gas properties depends on commodity prices. Declines in these prices as well as increases in development costs, changes in well performance, delays in asset development or deterioration of drilling results may result in our having to make material downward adjustments to our estimated proved reserves, and could result in an impairment charge and a corresponding write-down of the carrying amount of our oil and natural gas properties. Because substantially all of our reserves are natural gas, changes in natural gas prices have a more significant impact on our financial results.
We evaluate our oil and gas properties for impairment on a field-by-field basis whenever events or changes in circumstances indicate a property's carrying amount may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on our estimate of future commodity prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using a combination of assumptions management uses in its budgeting and forecasting process as well as historical and current prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. In the event that commodity prices decline, there could be a significant revision in the future.
Our producing properties are geographically concentrated in the Marcellus Shale in northeast Pennsylvania, making us vulnerable to risks associated with operating in one major geographic area.
Our producing properties are geographically concentrated in the Marcellus Shale in northeast Pennsylvania. At December 31, 2019 substantially all of our proved developed reserves and equivalent production were attributable to our properties located in the Marcellus Shale. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, state and local political forces and governmental regulation, processing or transportation capacity constraints, market limitations, severe weather events, water shortages or other conditions or interruption of the processing or transportation of oil, natural gas or NGLs in the region.
Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable.
In general, the production rate of oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Unless we successfully replace the reserves that we produce, our reserves will decline, eventually resulting in a decrease in natural gas production and lower revenues and cash flow from operations. Our future production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. We may not be
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able to replace reserves through our exploration, development and exploitation activities or by acquiring properties at acceptable costs. Low commodity prices may further limit the kinds of reserves that we can develop and produce economically.
Our reserve report estimates that production from our proved developed reserves as of December 31, 2019 will decrease at a rate of 13 percent, 26 percent, 18 percent and 14 percent during 2020, 2021, 2022 and 2023, respectively. Future development of proved undeveloped and other reserves currently not classified as proved developed producing will impact these rates of decline. Because of higher initial decline rates from newly developed reserves, we consider this pattern to be fairly typical.
Exploration, development and exploitation activities involve numerous risks that may result in, among other things, dry holes, the failure to produce natural gas and oil in commercial quantities and the inability to fully produce discovered reserves.
We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, if at all.
We make and expect to make substantial capital expenditures in connection with our development and production projects. We rely upon access to both our revolving credit facility and longer-term capital markets as sources of liquidity for any capital requirements not satisfied by cash flow from operations or other sources. Future challenges in the global financial system, including the capital markets, may adversely affect our business and our financial condition. Our ability to access the capital markets may be restricted at a time when we desire, or need, to raise capital, which could have an impact on our flexibility to react to changing economic and business conditions. Adverse economic and market conditions could adversely affect the collectability of our trade receivables and cause our commodity hedging counterparties to be unable to perform their obligations or to seek bankruptcy protection. Future challenges in the economy could also lead to reduced demand for natural gas which could have a negative impact on our revenues.
Risks associated with our debt and the provisions of our debt agreements could adversely affect our business, financial position and results of operations.
As of December 31, 2019, we had approximately $1.2 billion of debt outstanding and we may incur additional indebtedness in the future. Increases in our level of indebtedness may:
• | require us to use a substantial portion of our cash flow to make debt service payments, which will reduce the funds that would otherwise be available for operations, returning free cash flow to shareholders and future business opportunities; |
• | limit our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt, making certain investments, and paying dividends; |
• | place us at a competitive disadvantage compared to our competitors with lower debt service obligations; |
• | depending on the levels of our outstanding debt, limit our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes; and |
• | increase our vulnerability to downturns in our business or the economy, including declines in commodity prices. |
In addition, the margins we pay under our revolving credit facility depend on our leverage ratio. Accordingly, increases in the amount of our indebtedness without corresponding increases in our consolidated EBITDAX, or decreases in our EBITDAX without a corresponding decrease in our indebtedness, may result in an increase in our interest expense.
Our debt agreements also require compliance with covenants to maintain specified financial ratios. If commodity prices deteriorate from current levels or continue for an extended period, it could lead to reduced revenues, cash flow and earnings, which in turn could lead to a default due to lack of covenant compliance. Because the calculations of the financial ratios are made as of certain dates, the financial ratios can fluctuate significantly from period to period. A prolonged period of lower commodity prices could further increase the risk of our inability to comply with covenants to maintain specified financial ratios. In order to provide a margin of comfort with regard to these financial covenants, we may seek to reduce our capital expenditures, sell non-strategic assets or opportunistically modify or increase our derivative instruments to the extent permitted under our debt agreements. In addition, we may seek to refinance or restructure all or a portion of our indebtedness. We cannot provide assurance that we will be able to successfully execute any of these strategies, and such strategies may be unavailable on favorable terms or at all. For more information about our debt agreements, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Financial Condition - Capital Resources and Liquidity.”
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The borrowing base under our revolving credit facility may be reduced, which could limit us in the future.
The borrowing base under our revolving credit facility is currently $3.2 billion, and lender commitments under our revolving credit facility are $1.5 billion. The borrowing base is redetermined annually under the terms of our revolving credit facility on April 1. In addition, either we or the banks may request an interim redetermination twice a year or in conjunction with certain acquisitions or sales of oil and gas properties. Our borrowing base may decrease as a result of lower commodity prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for any other reason. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the redetermined borrowing base. In addition, we may be unable to access the equity or debt capital markets, including the market for senior unsecured notes, to meet our obligations, including any such debt repayment obligations.
Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our growth rate.
Our future growth prospects are dependent upon our ability to identify optimal strategies for our business. In developing our business plan, we considered allocating capital and other resources to various aspects of our businesses including well-development (primarily drilling), reserve acquisitions, exploratory activity, corporate items and other alternatives. We also considered our likely sources of capital. Notwithstanding the determinations made in the development of our 2020 plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, or fail to optimize our capital investment and capital raising opportunities and the use of our other resources in furtherance of our business strategies, our financial condition and growth rate may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our 2020 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, oil spills, greenhouse gas or methane emissions and explosions of natural gas transmission lines, may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.
Our ability to sell our natural gas production and/or the prices we receive for our production could be materially harmed if we fail to obtain adequate services such as transportation and processing.
The sale of our natural gas production depends on a number of factors beyond our control, including the availability and capacity of transportation and processing facilities. We deliver our natural gas production primarily through gathering systems and pipelines that we do not own. The lack of available capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Third-party systems and facilities may be unavailable due to market conditions or mechanical or other reasons. In addition, at current commodity prices, construction of new pipelines and building of such infrastructure may be slower to build out. To the extent these services are unavailable, we would be unable to realize revenue from wells served by such facilities until suitable arrangements are made to market our production. Our failure to obtain these services on acceptable terms could materially harm our business.
For example, the Marcellus Shale wells we have drilled to date have generally reported very high initial production rates. The amount of natural gas being produced in the area from these new wells, as well as natural gas produced from other existing wells, may exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available. In such an event, this could result in wells being shut in or awaiting a pipeline connection or capacity and/or natural gas being sold at much lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations and cash flows.
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We are subject to complex laws and regulations, including environmental and safety regulations, which can adversely affect the cost, manner or feasibility of doing business.
Our operations are subject to extensive federal, state and local laws and regulations, including drilling, permitting and safety laws and regulations and those relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These laws and regulations can adversely affect the cost, manner or feasibility of doing business. Many laws and regulations require permits for the operation of various facilities, and these permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with their regulations, and violations could subject us to fines, injunctions or both. These laws and regulations have increased the costs of planning, designing, drilling, installing and operating natural gas and oil facilities, and new laws and regulations or revisions or reinterpretations of existing laws and regulations could further increase these costs. In addition, we may be liable for environmental damages caused by previous owners or operators of property we purchase or lease. Risks of substantial costs and liabilities related to environmental compliance issues are inherent in natural gas and oil operations. For example, we could be required to install expensive pollution control measures or limit or cease activities on lands located within wilderness, wetlands or other environmentally or politically sensitive areas. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties as well as the imposition of corrective action orders. It is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from natural gas and oil production, would result in substantial costs and liabilities.
Acquired properties may not be worth what we pay due to uncertainties in evaluating recoverable reserves and other expected benefits, as well as potential liabilities.
Successful property acquisitions require an assessment of a number of factors beyond our control. These factors include estimates of recoverable reserves, exploration potential, future commodity prices, operating costs, production taxes and potential environmental and other liabilities. These assessments are complex and inherently imprecise. Our review of the properties we acquire may not reveal all existing or potential problems. In addition, our review may not allow us to fully assess the potential deficiencies of the properties. We do not inspect every well, and even when we inspect a well we may not discover structural, subsurface, or environmental problems that may exist or arise.
There may be threatened or contemplated claims against the assets or businesses we acquire related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We often assume certain liabilities, and we may not be entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities, and our contractual indemnification may not be effective. At times, we acquire interests in properties on an "as is" basis with limited representations and warranties and limited remedies for breaches of such representations and warranties. In addition, significant acquisitions can change the nature of our operations and business if the acquired properties have substantially different operating and geological characteristics or are in different geographic locations than our existing properties.
The integration of the businesses and properties we may acquire could be difficult, and may divert management's attention away from our existing operations.
The integration of the businesses and properties we may acquire could be difficult, and may divert management's attention and financial resources away from our existing operations. These difficulties include:
• | the challenge of integrating the acquired businesses and properties while carrying on the ongoing operations of our business; |
• | the inability to retain key employees of the acquired business; |
• | potential lack of operating experience in a geographic market of the acquired properties; and |
• | the possibility of faulty assumptions underlying our expectations. |
The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our existing business. If management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.
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We face a variety of hazards and risks that could cause substantial financial losses.
Our business involves a variety of operating risks, including:
• | well site blowouts, cratering and explosions; |
• | equipment failures; |
• | pipe or cement failures and casing collapses, which can release natural gas, oil, drilling fluids or hydraulic fracturing fluids; |
• | uncontrolled flows of natural gas, oil or well fluids; |
• | pipeline ruptures; |
• | fires; |
• | formations with abnormal pressures; |
• | handling and disposal of materials, including drilling fluids and hydraulic fracturing fluids; |
• | release of toxic gas; |
• | buildup of naturally occurring radioactive materials; |
• | pollution and other environmental risks, including conditions caused by previous owners or operators of our properties; and |
• | natural disasters. |
Any of these events could result in injury or loss of human life, loss of hydrocarbons, significant damage to or destruction of property, environmental pollution, regulatory investigations and penalties, suspension or impairment of our operations and substantial losses to us.
Our utilization of natural gas gathering and pipeline systems also involves various risks, including the risk of explosions and environmental hazards caused by pipeline leaks and ruptures. The location of pipelines near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks.
We may not be insured against all of the operating risks to which we are exposed.
We maintain insurance against some, but not all, operating risks and losses. We do not carry business interruption insurance. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
We have limited control over the activities on properties we do not operate.
Other companies operate some of the properties in which we have an interest. As of December 31, 2019, non-operated wells represented approximately nine percent of our total owned gross wells, or approximately one percent of our owned net wells. We have limited ability to influence or control the operation or future development of these non-operated properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator's breach of the applicable agreements or an operator's failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.
Competition in our industry is intense, and many of our competitors have substantially greater financial and technological resources than we do, which could adversely affect our competitive position.
Competition in the natural gas and oil industry is intense. Major and independent natural gas and oil companies actively bid for desirable natural gas and oil properties, as well as for the capital, equipment and labor required to operate and develop these properties. Our competitive position is affected by price, contract terms and quality of service, including pipeline connection times, distribution efficiencies and reliable delivery record. Many of our competitors have financial and technological resources and exploration and development budgets that are substantially greater than ours. These companies
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may be able to pay more for exploratory projects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on the existing and changing technologies that we believe will be increasingly important to attaining success in the industry. These companies may also have a greater ability to continue drilling activities during periods of low natural gas and oil prices and to absorb the burden of current and future governmental regulations and taxation.
We may have hedging arrangements that expose us to risk of financial loss and limit the benefit to us of increases in prices for natural gas.
From time to time, when we believe that market conditions are favorable, we use financial derivative instruments to manage price risk associated with our natural gas production. While there are many different types of derivatives available, we generally utilize collar, swap and basis swap agreements to manage price risk more effectively.
The collar arrangements are put and call options used to establish floor and ceiling prices for a fixed volume of production during a certain time period. They provide for payments to counterparties if the index price exceeds the ceiling and payments from the counterparties if the index price falls below the floor. The swap agreements call for payments to, or receipts from, counterparties based on whether the index price for the period is greater or less than the fixed price established for that period when the swap is put in place. These arrangements limit the benefit to us of increases in prices. In addition, these arrangements expose us to risks of financial loss in a variety of circumstances, including when:
• | there is an adverse change in the expected differential between the underlying price in the derivative instrument and actual prices received for our production; |
• | production is less than expected; or |
• | a counterparty is unable to satisfy its obligations. |
The CFTC has promulgated regulations to implement statutory requirements for swap transactions. These regulations are intended to implement a regulated market in which most swaps are executed on registered exchanges or swap execution facilities and cleared through central counterparties. While we believe that our use of swap transactions exempt us from certain regulatory requirements, the changes to the swap market due to increased regulation could significantly increase the cost of entering into new swaps or maintaining existing swaps, materially alter the terms of new or existing swap transactions and/or reduce the availability of new or existing swaps. If we reduce our use of swaps as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.
We will continue to evaluate the benefit of utilizing derivatives in the future. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7 and "Quantitative and Qualitative Disclosures about Market Risk" in Item 7A for further discussion concerning our use of derivatives.
The loss of key personnel could adversely affect our ability to operate.
Our operations are dependent upon a relatively small group of key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, our drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and some other professionals is extremely intense. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed.
Oil and natural gas production operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Our ability to produce natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.
Water is an essential component of oil and natural gas production during the drilling, and in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations. For water sourcing, we first seek to use non-potable water supplies for our operational needs. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must then be obtained from other sources and transported to the drilling site. An inability to secure sufficient amounts of water or to dispose of or recycle the water used in our operations could adversely impact our operations in certain areas. The imposition of new environmental regulations could further restrict our ability to conduct operations such as hydraulic fracturing by restricting the disposal of things such as produced water and drilling fluids.
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Federal and state legislation, judicial actions and regulatory initiatives related to oil and gas development, including hydraulic fracturing, could result in increased costs and operating restrictions or delays and adversely affect our business, financial condition, results of operations and cash flows.
Most of our exploration and production operations depend on the use of hydraulic fracturing to enhance production from oil and gas wells. This technology involves the injection of fluids—usually consisting mostly of water but typically including small amounts of several chemical additives—as well as sand or other proppants into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Most of our wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. Hydraulic fracturing operations have historically been overseen by state regulators as part of their oil and gas regulatory programs; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act and has released permitting guidance for hydraulic fracturing activities that use diesel in fracturing fluids in those states where the EPA is the permitting authority, including Pennsylvania. As a result, we may be subject to additional permitting requirements for hydraulic fracturing operations as well as various restrictions on those operations. These permitting requirements and restrictions could result in delays in operations at well sites as well as increased costs to make wells productive. Several candidates in the 2020 United States presidential campaign have indicated that they would support federal government efforts to limit or prohibit hydraulic fracturing. In addition, from time to time, legislation has been introduced, but not enacted, in Congress that would provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and require the public disclosure of certain information regarding the chemical makeup of hydraulic fracturing fluids. If enacted, this legislation could establish an additional level of regulation and permitting at the federal, state or local levels, and could make it easier for third parties opposed to the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect the environment, including groundwater, soil or surface water. In March 2015, the Department of the Interior's Bureau of Land Management issued a final rule to regulate hydraulic fracturing on public and Indian land; however, these rules were rescinded by rule in December 2017. We voluntarily disclose on a well-by-well basis the chemicals we use in the hydraulic fracturing process at www.fracfocus.org.
In addition, state and federal regulatory agencies recently have focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity. Similar concerns have been raised that hydraulic fracturing may also contribute to seismic activity. When caused by human activity, such events are called induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. In light of these concerns, some state regulatory agencies have modified their regulations or issued orders to address induced seismicity. Certain environmental and other groups have also suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process. We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. Increased regulation and attention given to induced seismicity could lead to greater opposition to, and litigation concerning, oil and gas activities utilizing hydraulic fracturing or injection wells for waste disposal, which could have an adverse effect on oil and natural gas production activities, including operational delays or increased operating costs in the production of oil and natural gas from developing shale plays, or could make it more difficult to perform hydraulic fracturing.
On August 16, 2012, the EPA published final rules that establish new air emission control requirements for natural gas and NGL production, processing and transportation activities, including NSPS to address emissions of sulfur dioxide and volatile organic compounds, and NESHAPS to address hazardous air pollutants frequently associated with gas production and processing activities. In June 2016, the EPA published a final rule that updates and expands the NSPS by setting additional emissions limits for volatile organic compounds and regulating methane emissions for new and modified sources in the oil and gas industry. In June 2017, the EPA proposed a two year stay of certain requirements contained in the June 2016 rule and in November 2017 issued a notice of data availability in support of the stay proposal and provided a 30-day comment period on the information provided. In March 2018, the EPA published a final rule that amended two narrow provisions of the NSPS, removing the requirement for completion of delayed repair during emergency or unscheduled vent blowdowns. A 2016 information collection request made to oil and natural gas facilities by the EPA in connection with its intention at the time to regulate methane emissions from existing sources were withdrawn in March 2017. The EPA also published a final rule in June 2016 concerning aggregation of sources that affects source determinations for air permitting in the oil and gas industry.
Compliance with these requirements, especially the new methane regulation, may require modifications to certain of our operations or increase the cost of new or modified facilities, including the installation of new equipment to control emissions at the well site that could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. Similarly, aggregating our oil and gas facilities for permitting could result in more complex, costly, and time consuming air permitting. Particularly in regard to obtaining pre-construction permits, the final aggregation rule could add costs and cause delays in our operations.
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In addition to these federal legislative and regulatory proposals, some states in which we operate, such as Pennsylvania, and certain local governments have adopted, and others are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, including requirements regarding chemical disclosure, casing and cementing of wells, withdrawal of water for use in high-volume hydraulic fracturing of horizontal wells, baseline testing of nearby water wells, and restrictions on the type of additives that may be used in hydraulic fracturing operations. For example, New York issued a statewide ban on hydraulic fracturing in June 2015. In addition, Pennsylvania's Act 13 of 2012 became law on February 14, 2012 and amended the state's Oil and Gas Act to, among other things, increase civil penalties and strengthen the Pennsylvania Department of Environmental Protection's (PaDEP) authority over the issuance of drilling permits. Although the Pennsylvania Supreme Court struck down portions of Act 13 that made statewide rules on oil and gas preempt local zoning rules, this could lead to additional local restrictions on oil and gas activity in the state. In addition, if existing laws and regulations with regard to hydraulic fracturing are revised or reinterpreted or if new laws and regulations become applicable to our operations through judicial or administrative actions, our business, financial condition, results of operations and cash flows could be adversely affected. For example, a Pennsylvania state trial court in 2018 refused to apply the established common law rule of capture in a case concerning claims of trespass by hydraulic fracturing. The Pennsylvania Supreme Court heard the appeal of this ruling and on January 22, 2020 affirmed the rule of capture and remanded the case to the Pennsylvania state trial court for further proceedings. Depending on the ultimate outcome at the Pennsylvania state trial court, this case could still have a material impact on our operations.
We use a significant amount of water in our hydraulic fracturing operations. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our operations, could adversely impact our operations. Moreover, new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition. For example, in April 2011, PaDEP called on all Marcellus Shale natural gas drilling operators to voluntarily cease by May 19, 2011 delivering wastewater to those centralized treatment facilities that were grandfathered from the application of PaDEP's Total Dissolved Solids regulations. In June 2016, the EPA published final pretreatment standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works. The regulations were developed under the EPA's Effluent Guidelines Program under the authority of the Clean Water Act. In response to these actions, operators including us have begun to rely more on recycling of flowback and produced water from well sites as a preferred alternative to disposal.
A number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing practices. For example, the EPA conducted a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The EPA released its final report in December 2016. It concluded that hydraulic fracturing activities can impact drinking water resources under some circumstances, including large volume spills and inadequate mechanical integrity of wells. This study and other studies that may be undertaken by the EPA or other federal agencies could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act, the Toxic Substances Control Act, or other statutory and/or regulatory mechanisms.
Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for the oil and natural gas that we produce.
Scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” (GHGs), including carbon dioxide and methane, may be contributing to warming of the earth’s atmosphere and other climatic changes. In response to such studies, the issue of climate change and the effect of GHG emissions, in particular emissions from fossil fuels, has and continues to attract political and social attention. The regulatory response to and physical effects of climate change have the potential to negatively affect our business in many ways, including increasing the costs to provide our products and services, reducing the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks.
Legislation to regulate GHG emissions has periodically been introduced in the U.S. Congress and such legislation may be proposed or adopted in the future. In addition, the EPA has adopted regulations addressing GHG emissions. In 2009 and 2010, the EPA adopted rules requiring the monitoring, reporting and recordkeeping of GHG emissions from specified sources in the United States, including onshore and offshore oil and natural gas production facilities that emit 25,000 metric tons or more of CO2e per year. Since 2012, we have been required to report our GHG emissions to the EPA each year in March under these rules and have submitted our annual reports in compliance with the deadline. In 2015, the EPA finalized rules adding additional sources to the scope of the GHG monitoring and reporting requirements, including gathering and boosting facilities as well as completions and workovers from hydraulically fractured oil wells, and adding well identification reporting requirements for
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certain facilities. The EPA published a final rule in 2016 adding monitoring methods for detecting leaks from oil and gas equipment and emission factors for leaking equipment to be used to calculate and report GHG emissions resulting from equipment leaks. In addition to the GHG monitoring and reporting rules, the EPA adopted rules requiring permits for GHGs for certain large stationary sources beginning in 2011. However, in 2014, the U.S. Supreme Court, in Utility Air Regulatory Group v. EPA, limited the application of the GHG permitting requirements under the Prevention of Significant Deterioration and Title V permitting programs to sources that would otherwise need permits based on the emission of conventional pollutants. A discussion of federal methane regulations is provided in the preceding risk factor.
There have also been international efforts seeking legally binding reductions in GHG emissions. The United States was actively involved in the negotiations at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris (the “UNFCCC”), which led to the creation of the Paris Agreement. The Paris Agreement requires countries to review and "represent a progression" in their nationally determined contributions, which set emissions reduction goals, every five years. The United States was a signatory to the Paris Agreement, which entered into full force in November 2016. On June 1, 2017, the President of the United States announced that the United States planned to withdraw from the Paris Agreement and to seek negotiations to either reenter the Paris Agreement on different terms or establish a new framework agreement. The earliest possible effective date for the United States withdrawal is November 4, 2020, which is four years from the date the agreement took effect. The United States’ adherence to the exit process is uncertain, and the terms on which the United States may reenter the Paris Agreement, or a separately negotiated agreement are unclear at this time.
It is not possible at this time to predict the timing and effect of climate change or to predict the effect of the Paris Agreement or whether additional GHG legislation, regulations or other measures will be adopted at the federal, state or local levels. However, more aggressive efforts by governments and non-governmental organizations to reduce GHG emissions appear likely and any such future laws and regulations could result in increased compliance costs or additional operating restrictions. For example, several U.S. states and cities have committed to advance the objectives of the Paris Agreement at the state or local level despite the pending federal withdrawal.
The passage of any federal or state climate change laws or regulations in the future could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy.
Beyond financial and regulatory impacts, climate change poses potential physical risks. Scientific studies forecast that these risks include an increase in sea level, stresses on water supply and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. The projected physical effects of climate change have the potential to directly affect, delay and result in increased costs related to our operations. In addition, warmer winters as a result of global warming could also decrease demand for natural gas. However, because the nature and timing of changes in extreme weather events (such as increased frequency, duration, and severity) are uncertain, any estimations of future financial risk to our operations caused by these potential physical risks of climate change would be unreliable.
Terrorist activities and the potential for military and other actions could adversely affect our business.
The threat of terrorism and the impact of military and other action have caused instability in world financial markets and could lead to increased volatility in prices for natural gas and oil, all of which could adversely affect the markets for our operations. Acts of terrorism, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, could be directed against companies operating in the United States. The U.S. government has issued public warnings that indicate energy assets might be specific targets of terrorist organizations. These developments have subjected our operations to increased risk and, depending on their ultimate magnitude, could have a material adverse effect on our business.
Cyber-attacks targeting our systems, the oil and gas industry systems and infrastructure, or the systems of our third-party service providers could adversely affect our business.
Our business and the oil and gas industry in general have become increasingly dependent on digital data, computer networks and connected infrastructure, including technologies that are managed by third-party providers on whom we rely to help us collect, host or process information. We depend on this technology to record and store financial data, estimate quantities of natural gas and crude oil reserves, analyze and share operating data and communicate internally and externally. Computers
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control nearly all of the oil and gas distribution systems in the United States, which are necessary to transport our products to market, to enable communications and to provide a host of other support services for our business.
Cyber-attacks are becoming more sophisticated and include, but are not limited to, malicious software, phishing, ransomware, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Unauthorized access to our seismic data, reserves information, customer or employee data or other proprietary or commercially sensitive information could lead to data corruption, communication interruption, or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our results of operations. If our information technology systems cease to function properly or our cybersecurity is breached, we could suffer disruptions to our normal operations, which may include drilling, completion, production and corporate functions. A cyber-attack involving our information systems and related infrastructure, or that of our business associates, could result in supply chain disruptions that delay or prevent the transportation and marketing of our production, non-compliance leading to regulatory fines or penalties, loss or disclosure of, or damage to, our or any of our customer’s or supplier’s data or confidential information that could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.
In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period, and our systems and insurance coverage for protecting against such cybersecurity risks may not be sufficient. As cyber-attackers become more sophisticated, we may be required to expend significant additional resources to continue to protect our business or remediate the damage from cyber-attacks. Furthermore, the continuing and evolving threat of cyber-attacks has resulted in increased regulatory focus on prevention, and we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. To the extent we face increased regulatory requirements, we may be required to expend significant additional resources to meet such requirements.
We are subject to a number of privacy and data protection laws, rules and directives (collectively, “data protection laws”) relating to the processing of personal data.
The regulatory environment surrounding data protection laws is uncertain. Complying with varying jurisdictional requirements could increase the costs and complexity of compliance, and violations of applicable data protection laws can result in significant penalties. A determination that there have been violations of applicable data protection laws could expose us to significant damage awards, fines and other penalties that could materially harm our business and reputation.
Any failure, or perceived failure, by us to comply with applicable data protection laws could result in proceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments and negative publicity, require us to change our business practices, increase the costs and complexity of compliance, and adversely affect our business. As noted above, we are also subject to the possibility of security and privacy breaches, which themselves may result in a violation of these laws. Additionally, the acquisition of a company that is not in compliance with applicable data protection laws may result in a violation of these laws.
Tax law changes could have an adverse effect on our financial position, results of operations, and cash flows.
On December 22, 2017, the U.S. enacted legislation referred to as the Tax Cuts and Jobs Act (the Tax Act). The Tax Act significantly changed U.S. corporate income tax laws beginning, generally, in 2018. Refer to Note 11 of the Notes to the Consolidated Financial Statements, Income Taxes, for a discussion on the impact of the Tax Act on us. There exist various uncertainties and ambiguities in the application of certain provisions of the Tax Act. In the absence of guidance, we have used what we believe are reasonable interpretations and assumptions in applying the Tax Act. It is possible that the Internal Revenue Service could issue subsequent regulations or other guidance or take positions on audit that differ from our prior interpretations and assumptions, which could adversely impact our financial position, results of operations, and cash flows.
While the Tax Act maintained many of the tax incentives and deductions that are used by U.S. oil and gas companies, including the percentage depletion allowance for oil and natural gas companies, the ability to fully deduct intangible drilling costs in the year incurred, and the current amortization period of geological and geophysical expenditures for independent producers, the U.S. tax law is always subject to change. Periodically, legislation is proposed to repeal these industry tax incentives and deductions, and/or to impose new industry taxes. In addition, various states are still determining if and to what extent they will conform to the Tax Act. Further, many states are currently in deficits, and have been enacting laws eliminating or limiting certain deductions, carryforwards, and credits in order to increase tax revenue.
Should the U.S. or the states publish guidance or pass tax legislation limiting any currently allowed tax incentives and deductions, our taxes would increase, potentially significantly, which would have a negative impact on our net income and cash
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flows. This could also reduce our drilling activities in the U.S. Since future changes to federal and state tax legislation and regulations are unknown, we cannot know the ultimate impact such changes may have on our business.
Provisions of Delaware law and our bylaws and charter could discourage change in control transactions and prevent stockholders from receiving a premium on their investment.
Our charter authorizes our Board of Directors to set the terms of preferred stock. In addition, Delaware law contains provisions that impose restrictions on business combinations with interested parties. Our bylaws prohibit the calling of a special meeting by our stockholders and place procedural requirements and limitations on stockholder proposals at meetings of stockholders. Because of these provisions of our charter, bylaws and Delaware law, persons considering unsolicited tender offers or other unilateral takeover proposals may be more likely to negotiate with our Board of Directors rather than pursue non-negotiated takeover attempts. As a result, these provisions may make it more difficult for our stockholders to benefit from transactions that are opposed by an incumbent Board of Directors.
The personal liability of our directors for monetary damages for breach of their fiduciary duty of care is limited by the Delaware General Corporation Law and by our charter.
The Delaware General Corporation Law allows corporations to limit available relief for the breach of directors' duty of care to equitable remedies such as injunction or rescission. Our charter limits the liability of our directors to the fullest extent permitted by Delaware law. Specifically, our directors will not be personally liable for monetary damages for any breach of their fiduciary duty as a director, except for liability:
• | for any breach of their duty of loyalty to the Company or our stockholders; |
• | for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law; |
• | under provisions relating to unlawful payments of dividends or unlawful stock repurchases or redemptions; and |
• | for any transaction from which the director derived an improper personal benefit. |
This limitation may have the effect of reducing the likelihood of derivative litigation against directors, and may discourage or deter stockholders or management from bringing a lawsuit against directors for breach of their duty of care, even though such an action, if successful, might otherwise have benefited our stockholders.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 3. LEGAL PROCEEDINGS
Legal Matters
The information set forth under the heading "Legal Matters" in Note 9 of the Notes to Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K is incorporated by reference in response to this item.
Environmental Matters
On June 17, 2019, we received two proposed Consent Order and Agreements (CO&A) from the Pennsylvania Department of Environmental Protection (PaDEP) relating to gas migration allegations in areas surrounding several wells owned and operated by us in Susquehanna County, Pennsylvania. The allegations relating to these wells were initially raised by residents in the area in March and June 2017, respectively, in the form of complaints about their drinking water supply. Since then, we have been engaged with the PaDEP in investigating the incidents and have performed appropriate remediation efforts, including the provision of alternative sources of drinking water to the affected residents. We received Notices of Violation (NOV) from the PaDEP in June and November, 2017, respectively, for failure to prevent the migration of gas into fresh groundwater sources in the area surrounding these wells. With regard to the June 2017 NOV, we believe these water quality complaints have been resolved, and we are working with the PaDEP to reach agreement on the disposition of this matter. The proposed CO&A is the culmination of this effort and, if finalized, would result in the payment of a civil monetary penalty in an amount likely to exceed $100,000, up to approximately $215,000. We will continue to work with the PaDEP to finalize the CO&A, and to bring this matter to a close. With regard to the November 2017 NOV, the proposed CO&A, if finalized as drafted, would require Cabot to submit a detailed written remediation plan, continue water sampling and other investigative measures and restore or replace affected water supplies and would result in the payment of a civil monetary penalty in an amount likely to exceed $100,000, up to approximately $355,000. We will continue to work with the PaDEP to finalize the CO&A, and to complete the ongoing investigation and remediation.
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From time to time we receive notices of violation from governmental and regulatory authorities in areas in which we operate relating to alleged violations of environmental statutes or the rules and regulations promulgated thereunder. While we cannot predict with certainty whether these notices of violation will result in fines and/or penalties, if fines and/or penalties are imposed, they may result in monetary sanctions, individually or in the aggregate, in excess of $100,000.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table shows certain information as of February 19, 2020 about our executive officers, as such term is defined in Rule 3b-7 of the Securities Exchange Act of 1934, and certain of our other officers.
Name | Age | Position | Officer Since | ||||
Dan O. Dinges | 66 | Chairman, President and Chief Executive Officer | 2001 | ||||
Scott C. Schroeder | 57 | Executive Vice President and Chief Financial Officer | 1997 | ||||
Jeffrey W. Hutton | 64 | Senior Vice President, Marketing | 1995 | ||||
Todd L. Liebl | 62 | Senior Vice President, Land and Business Development | 2012 | ||||
Steven W. Lindeman | 59 | Senior Vice President, EHS and Engineering | 2011 | ||||
Phillip L. Stalnaker | 60 | Senior Vice President, Operations | 2009 | ||||
G. Kevin Cunningham | 66 | Vice President and General Counsel | 2010 | ||||
Charles E. Dyson II | 48 | Vice President, Information Services | 2018 | ||||
Matthew P. Kerin | 39 | Vice President, Finance and Treasurer | 2014 | ||||
Julius Leitner | 57 | Vice President, Marketing | 2017 | ||||
Todd M. Roemer | 49 | Vice President and Chief Accounting Officer | 2010 | ||||
Deidre L. Shearer | 52 | Vice President, Administration and Corporate Secretary | 2012 | ||||
All officers are elected annually by our Board of Directors. All of the executive officers have been employed by Cabot Oil & Gas Corporation for at least the last five years, except for Mr. Charles E. Dyson II and Mr. Julius Leitner.
Mr. Dyson joined the Company as the Director of Information Services in October 2015 and was promoted to Vice President of Information Services in February 2018. Prior to joining the Company, he served as the Director of Infrastructure and Support Services at Transocean Offshore Deepwater Drilling, Inc. Mr. Dyson holds a Bachelor of Business Administration degree in Finance from Texas A&M University.
Mr. Leitner joined the Company as Vice President, Marketing in July 2017. Prior to joining the Company, Mr. Leitner held various positions with Shell Energy North America (US) L.P., including Director of Northeast Trading, Director of Producer Services, and Senior Originator, from July 1996 through July 2017. Mr. Leitner holds a Bachelor of Science degree in Biology from Boston College and a Masters of Business Administration from the Mays Business School of Texas A&M University.
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PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is listed and principally traded on the New York Stock Exchange under the ticker symbol "COG."
As of February 1, 2020, there were 345 registered holders of our common stock.
In April 2019, the Board of Directors approved an increase in the quarterly dividend on our common stock from $0.07 per share to $0.09 per share. In October 2019, the Board of Directors approved an additional increase in the quarterly dividend on our common stock from $0.09 per share to $0.10 per share.
EQUITY COMPENSATION PLAN INFORMATION
The following table provides information as of December 31, 2019 regarding the number of shares of common stock that may be issued under our incentive plans.
(a) | (b) | (c) | ||||||
Plan Category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted-average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | |||||
Equity compensation plans approved by security holders | 3,954,928 | (1) | n/a | 12,842,600 | (2) | |||
Equity compensation plans not approved by security holders | n/a | n/a | n/a | |||||
Total | 3,954,928 | n/a | 12,842,600 | |||||
_______________________________________________________________________________
(1) | Includes 1,259,287 employee performance shares, the performance periods of which end on December 31, 2019, 2020 and 2021; 1,428,634 TSR performance shares, the performance periods of which end on December 31, 2019, 2020 and 2021; 692,788 hybrid performance shares, which vest, if at all, in 2020, 2021 and 2022; and 574,219 restricted stock units awarded to the non-employee directors, the restrictions on which lapse upon a non-employee director's departure from the Board of Directors. |
(2) | Includes 58,834 shares of restricted stock, the restrictions on which lapse on various dates in 2020, 2021 and 2022; and 12,783,766 shares that are available for future grants under the 2014 Incentive Plan. |
ISSUER PURCHASES OF EQUITY SECURITIES
Our Board of Directors has authorized a share repurchase program under which we may purchase shares of common stock in the open market or in negotiated transactions. In July 2019, the Board of Directors authorized an increase of 25.0 million shares to our share repurchase program. There is no expiration date associated with the authorization. The shares included in the table below were repurchased on the open market and were held as treasury stock as of December 31, 2019.
Period | Total Number of Shares Purchased | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs | |||||||||
October 2019 | — | $ | — | — | 21,032,682 | ||||||||
November 2019 | 5,250,000 | $ | 17.76 | 5,250,000 | 15,782,682 | ||||||||
December 2019 | 4,750,000 | $ | 16.62 | 4,750,000 | 11,032,682 | ||||||||
Total | 10,000,000 | 10,000,000 | |||||||||||
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PERFORMANCE GRAPH
The following graph compares our common stock performance (COG) with the performance of the Standard & Poor's 500 Stock Index and the Dow Jones U.S. Exploration & Production Index for the period December 2014 through December 2019. The graph assumes that the value of the investment in our common stock and in each index was $100 on December 31, 2014 and that all dividends were reinvested.
December 31, | |||||||||||||||||||||||
Calculated Values | 2014 | 2015 | 2016 | 2017 | 2018 | 2019 | |||||||||||||||||
COG | $ | 100.00 | $ | 59.92 | $ | 79.42 | $ | 97.89 | $ | 77.26 | $ | 61.21 | |||||||||||
S&P 500 | $ | 100.00 | $ | 101.38 | $ | 113.51 | $ | 138.29 | $ | 132.23 | $ | 173.86 | |||||||||||
Dow Jones U.S. Exploration & Production | $ | 100.00 | $ | 76.27 | $ | 94.94 | $ | 96.18 | $ | 79.09 | $ | 88.10 | |||||||||||
The performance graph above is furnished and not filed for purposes of Section 18 of the Securities Exchange Act of 1934 (the Exchange Act) and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933 unless specifically identified therein as being incorporated therein by reference. The performance graph is not soliciting material subject to Regulation 14A of the Exchange Act.
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ITEM 6. SELECTED FINANCIAL DATA
The following table summarizes our selected consolidated financial data for the periods indicated. This information should be read in conjunction with Management's Discussion and Analysis of Financial Condition and Results of Operations in Item 7, and the Consolidated Financial Statements and related Notes in Item 8.
Year Ended December 31, | |||||||||||||||||||
(In thousands, except per share amounts) | 2019 | 2018 | 2017 | 2016 | 2015 | ||||||||||||||
Statement of Operations Data | |||||||||||||||||||
Operating revenues | $ | 2,066,277 | $ | 2,188,148 | $ | 1,764,219 | $ | 1,155,677 | $ | 1,357,150 | |||||||||
Impairment of oil and gas properties(1) | — | — | 482,811 | 435,619 | 114,875 | ||||||||||||||
Earnings (loss) on equity method investments(2) | 80,496 | 1,137 | (100,486 | ) | (2,477 | ) | 6,415 | ||||||||||||
Gain (loss) on sale of assets(3) | (1,462 | ) | (16,327 | ) | (11,565 | ) | (1,857 | ) | 3,866 | ||||||||||
Income (loss) from operations | 955,750 | 771,801 | (151,260 | ) | (564,945 | ) | (88,914 | ) | |||||||||||
Net income (loss)(4) | 681,070 | 557,043 | 100,393 | (417,124 | ) | (113,891 | ) | ||||||||||||
Basic earnings (loss) per share | $ | 1.64 | $ | 1.25 | $ | 0.22 | $ | (0.91 | ) | $ | (0.28 | ) | |||||||
Diluted earnings (loss) per share | $ | 1.63 | $ | 1.24 | $ | 0.22 | $ | (0.91 | ) | $ | (0.28 | ) | |||||||
Dividends per common share | $ | 0.35 | $ | 0.25 | $ | 0.17 | $ | 0.08 | $ | 0.08 | |||||||||
December 31, | |||||||||||||||||||
(In thousands) | 2019 | 2018 | 2017 | 2016 | 2015 | ||||||||||||||
Balance Sheet Data | |||||||||||||||||||
Properties and equipment, net | $ | 3,855,706 | $ | 3,463,606 | $ | 3,072,204 | $ | 4,250,125 | $ | 4,976,879 | |||||||||
Total assets(5) | 4,487,245 | 4,198,829 | 4,727,344 | 5,122,569 | 5,253,038 | ||||||||||||||
Current portion of long-term debt | 87,000 | — | 304,000 | — | 20,000 | ||||||||||||||
Long-term debt | 1,133,025 | 1,226,104 | 1,217,891 | 1,520,530 | 1,996,139 | ||||||||||||||
Stockholders' equity | 2,151,487 | 2,088,159 | 2,523,905 | 2,567,667 | 2,009,188 | ||||||||||||||
(1) | Impairment of oil and gas properties in 2017 includes an impairment charge of $414.3 million associated with our oil and gas properties located in the Eagle Ford Shale in south Texas and $68.6 million associated with our oil and gas properties located in West Virginia and Ohio. Impairment of oil and gas properties in 2016 includes an impairment charge of $435.6 million associated with the proposed sale our oil and gas properties located in West Virginia and Ohio. Impairment of oil and gas properties in 2015 includes an impairment charge of $114.9 million associated with our oil and gas properties located in south Texas, east Texas and Louisiana. For additional discussion of impairment of oil and gas properties, refer to Note 1 and Note 3 of the Notes to the Consolidated Financial Statements. |
(2) | Earnings (loss) on equity method investments in 2019 includes a gain on sale of investment of $75.8 million associated with our equity investment in Meade Pipeline Co LLC (Meade). Earnings (loss) on equity method investments in 2017 includes an other than temporary impairment of $95.9 million associated with our investment in Constitution Pipeline Company, LLC (Constitution). Refer to Note 4 of the Notes to the Consolidated Financial Statements. |
(3) | Gain (loss) on sale of assets in 2018 includes a $45.4 million loss from the sale of certain proved and unproved oil and gas properties located in the Eagle Ford Shale partially offset by a $29.7 million gain from the sale of certain proved and unproved oil and gas properties located in the Haynesville Shale. Gain (loss) on sale of assets in 2017 includes an $11.9 million loss from the sale of certain proved and unproved oil and gas properties located in West Virginia, Virginia and Ohio. Refer to Note 2 of the Notes to the Consolidated Financial Statements. |
(4) | Net income (loss) in 2017 includes an income tax benefit of $242.9 million as a result of the remeasurement of our net deferred income tax liabilities based on the new lower corporate income tax rate associated with the Tax Act that was enacted in December 2017. Refer to Note 11 of the Notes to the Consolidated Financial Statements. |
(5) | Total assets as of December 31, 2019 include a right of use asset of $35.9 million as a result of the adoption of Accounting Standards Update No. 2016-02, Leases effective January 1, 2019. Comparative periods were not restated. Refer to Note 1 of the Notes to the Consolidated Financial Statements. |
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying Notes to the Consolidated Financial Statements included elsewhere in this Annul Report on Form 10-K contain additional information that should be referred to when reviewing this material.
OVERVIEW
Financial and Operating Overview
Financial and operating results for the year ended December 31, 2019 compared to the year ended December 31, 2018 are as follows:
• | Natural gas production increased 135.4 Bcf, or 19 percent, from 729.9 Bcf in 2018 to 865.3 Bcf in 2019, as a result of drilling and completion activities in the Marcellus Shale. |
• | Equivalent production increased 130.3 Bcfe, or 18 percent, from 735.0 Bcfe, or 2,013.7 Mmcfe per day, in 2018 to 865.3 Bcfe, or 2,370.9 Mmcfe per day, in 2019. The increase is primarily due to drilling and completion activities in the Marcellus Shale, partially offset by the sale of our Eagle Ford Shale assets in south Texas in February 2018. |
• | Average realized natural gas price for 2019 was $2.45 per Mcf, 4 percent lower than the $2.54 per Mcf price realized in 2018. |
• | Total capital expenditures were $783.3 million in 2019 compared to $816.1 million in 2018. |
• | Drilled 96 gross wells (94.0 net) with a success rate of 100.0 percent in 2019 compared to 97 gross wells (95.1 net) with a success rate of 90.7 percent in 2018. |
• | Completed 99 gross wells (97.0 net) in 2019 compared to 94 gross wells (93.0 net) in 2018. |
• | Average rig count during 2019 was approximately 3.1 rigs in the Marcellus Shale, compared to an average rig count in the Marcellus Shale of approximately 3.5 rigs and approximately 0.5 rigs in other areas during 2018. |
• | Repurchased 25.5 million shares of our common stock for a total cost of $488.5 million in 2019 compared to 38.5 million shares of common stock for a total cost of $904.1 million in 2018. |
• | Received proceeds of $249.5 million, including restricted cash of $13.6 million, related to the sale of our equity investment in Meade in November 2019. |
Market Conditions and Commodity Prices
Our financial results depend on many factors, particularly the commodity prices and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by pipeline capacity constraints, inventory storage levels, basis differentials, weather conditions and other factors. In addition, our realized prices are further impacted by our hedging activities. As a result, we cannot accurately predict future commodity prices and, therefore, cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenues. We expect commodity prices to remain volatile. In addition to production volumes and commodity prices, finding and developing sufficient amounts of natural gas and crude oil reserves at economical costs are critical to our long-term success. For information about the impact of realized commodity prices on our revenues, refer to "Results of Operations" below. Refer to "Risk Factors—Commodity prices fluctuate widely, and low prices for an extended period would likely have a material adverse impact on our business" and "Risk Factors—Our future performance depends on our ability to find or acquire additional natural gas and oil reserves that are economically recoverable" in Item 1A.
We account for our derivative instruments on a mark-to-market basis with changes in fair value recognized in operating revenues in the Consolidated Statement of Operations. As a result of these mark-to-market adjustments associated with our derivative instruments, we will experience volatility in our earnings due to commodity price volatility. Refer to “Impact of Derivative Instruments on Operating Revenues” below and Note 6 of the Notes to the Consolidated Financial Statements for more information.
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Commodity prices have been and are expected to remain volatile. We believe that we are well-positioned to manage the challenges presented in a volatile commodity pricing environment by:
• | Continuing to exercise discipline in our capital program with the expectation of funding our capital expenditures with cash on hand, operating cash flows, and if required, borrowings under our revolving credit facility. |
• | Continuing to optimize our drilling, completion and operational efficiencies, resulting in lower operating costs per unit of production. |
• | Continuing to manage our balance sheet, which we believe provides sufficient availability under our revolving credit facility and existing cash balances to meet our capital requirements and maintain compliance with our debt covenants. |
• | Continuing to manage price risk by strategically hedging our production. |
While we are unable to predict future commodity prices, in the event that commodity prices significantly decline, management would test the recoverability of the carrying value of its oil and gas properties and, if necessary, record an impairment charge.
FINANCIAL CONDITION
Capital Resources and Liquidity
Our primary sources of cash in 2019 were from the sale of natural gas production and proceeds from the sale of our equity investment in Meade. These cash flows were primarily used to fund our capital expenditures, interest payments on debt, repurchases of shares of our common stock, payment of dividends and contributions to our equity method investments. See below for additional discussion and analysis of cash flow.
On April 22, 2019, we entered into a second amended and restated credit agreement (revolving credit facility). The borrowing base under the terms of our revolving credit facility is redetermined annually in April. In addition, either we or the banks may request an interim redetermination twice a year or in connection with certain acquisitions or divestitures of oil and gas properties. The borrowing base and available commitments were reaffirmed at $3.2 billion and $1.5 billion, respectively. As of December 31, 2019, there were no borrowings outstanding under our revolving credit facility and our unused commitments remained at $1.5 billion.
A decline in commodity prices could result in the future reduction of our borrowing base and related commitments under our revolving credit facility. Unless commodity prices decline significantly from current levels, we do not believe that any such reductions would have a significant impact on our ability to service our debt and fund our drilling program and related operations.
We strive to manage our debt at a level below the available credit line in order to maintain borrowing capacity. Our revolving credit facility includes a covenant limiting our total debt. We believe that, with internally generated operating cash flow, cash on hand and availability under our revolving credit facility, we have the capacity to finance our spending plans.
At December 31, 2019, we were in compliance with all restrictive financial covenants for both our revolving credit facility and senior notes. Refer to Note 5 of the Notes to the Consolidated Financial Statements for further details regarding restrictive covenants.
Cash Flows
Our cash flows from operating activities, investing activities and financing activities are as follows:
Year Ended December 31, | |||||||||||
(In thousands) | 2019 | 2018 | 2017 | ||||||||
Cash flows provided by operating activities | $ | 1,445,791 | $ | 1,104,903 | $ | 898,160 | |||||
Cash flows used in investing activities | (543,915 | ) | (293,383 | ) | (706,153 | ) | |||||
Cash flows used in financing activities | (690,380 | ) | (1,289,280 | ) | (210,502 | ) | |||||
Net increase (decrease) in cash, cash equivalents and restricted cash | $ | 211,496 | $ | (477,760 | ) | $ | (18,495 | ) | |||
Operating Activities. Operating cash flow fluctuations are substantially driven by commodity prices, changes in our production volumes and operating expenses. Commodity prices have historically been volatile, primarily as a result of supply
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and demand for natural gas and crude oil, pipeline infrastructure constraints, basis differentials, inventory storage levels and seasonal influences. In addition, fluctuations in cash flow may result in an increase or decrease in our capital expenditures.
Our working capital is substantially influenced by the variables discussed above and fluctuates based on the timing and amount of borrowings and repayments under our revolving credit facility, repayments of debt, the timing of cash collections and payments on our trade accounts receivable and payable, respectively, payment of dividends, repurchases of our securities and changes in the fair value of our commodity derivative activity. From time to time, our working capital will reflect a deficit, while at other times it will reflect a surplus. This fluctuation is not unusual. At December 31, 2019 and 2018, we had a working capital surplus of $240.2 million and $257.3 million, respectively. We believe we have adequate liquidity and availability under our revolving credit facility to meet our working capital requirements over the next twelve months.
Net cash provided by operating activities in 2019 increased by $340.9 million compared to 2018. This increase was primarily due to an increase in cash received in settlement of derivatives, higher natural gas revenue, lower operating expenses and favorable changes in working capital and other assets and liabilities. These increases were partially offset by a decrease in brokered natural gas revenue. The increase in natural gas revenue was due to higher equivalent production, partially offset by a